Methods of completing a well and apparatus therefor

ABSTRACT

A method can include conveying a dispensing tool through a wellbore, the dispensing tool including an enclosure containing plugging devices, and then opening the enclosure by cutting a material of the enclosure, thereby releasing the plugging devices from the enclosure into the wellbore at a downhole location. A dispensing tool can include a container having an enclosure therein, the enclosure including a flexible material that contains the plugging devices, and an end of the enclosure being secured to a member displaceable by an actuator. The enclosure material is cut in response to displacement of the member by the actuator. A plugging device can include at least one body configured to engage an opening in the well and block fluid flow through the opening, and multiple fibers including staple fibers or filaments formed into yarn.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of the filing date of U.S.provisional application No. 62/433,459 filed on 13 Dec. 2016. The entiredisclosure of this prior application is incorporated herein by thisreference.

BACKGROUND

This disclosure relates generally to equipment utilized and operationsperformed in conjunction with a subterranean well and, in examplesdescribed below, more particularly provides methods and apparatus forcompleting a well.

It can be beneficial to be able to control how and where fluid flows ina well. For example, it may be desirable in some circumstances to beable to prevent fluid from flowing into a particular formation zone. Asanother example, it may be desirable in some circumstances to causefluid to flow into a particular formation zone, instead of into anotherformation zone. As yet another example, it may be desirable totemporarily prevent fluid from flowing through a passage of a well tool.Therefore, it will be readily appreciated that improvements arecontinually needed in the art of controlling fluid flow in wells.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representative partially cross-sectional view of an exampleof a well system and associated method which can embody principles ofthis disclosure, wherein a perforating assembly is being displaced intoa well.

FIG. 2 is a representative partially cross-sectional view of the systemand method of FIG. 1, wherein flow conveyed plugging devices are beingreleased from a container of the perforating assembly.

FIG. 3 is a representative partially cross-sectional view of the systemand method, wherein a formation zone is perforated.

FIGS. 4A & B are enlarged scale representative elevational views ofexamples of a flow conveyed plugging device that may be used in thesystem and method of FIGS. 1-3, and which can embody the principles ofthis disclosure.

FIG. 5 is a representative elevational view of another example of theflow conveyed plugging device.

FIGS. 6A & B are representative partially cross-sectional views of theflow conveyed plugging device in a well, the device being conveyed byflow in FIG. 6A, and engaging a casing opening in FIG. 6B.

FIGS. 7-9 are representative elevational views of examples of the flowconveyed plugging device with a retainer.

FIGS. 10 & 11 are representative cross-sectional views of additionalexamples of the flow conveyed plugging device.

FIGS. 12A & B are representative cross-sectional views of an example ofthe dispensing tool in respective run-in and actuated configurations.

FIG. 13 is a representative perspective view of an example of anenclosure of the dispensing tool.

FIG. 14 is a representative cross-sectional view of an attachmentbetween the enclosure and a valve closure member of the dispensing tool.

DETAILED DESCRIPTION

Example methods described below allow existing fluid passageways to beblocked permanently or temporarily in a variety of differentapplications. Certain flow conveyed plugging device examples describedbelow can be made of a fibrous material and may comprise a central body,a “knot” or other enlarged geometry.

The devices may be conveyed into the passageways or leak paths usingpumped fluid. Fibrous material extending outwardly from a body of adevice can “find” and follow the fluid flow, pulling the enlargedgeometry or fibers into a restricted portion of a flow path, causing theenlarged geometry and additional strands to become tightly wedged intothe flow path, thereby sealing off fluid communication.

The devices can be made of degradable or non-degradable materials. Thedegradable materials can be either self-degrading, or can requiredegrading treatments, such as, by exposing the materials to certainacids, certain base compositions, certain chemicals, certain types ofradiation (e.g., electromagnetic or “nuclear”), or elevated temperature.The exposure can be performed at a desired time using a form of wellintervention, such as, by spotting or circulating a fluid in the well sothat the material is exposed to the fluid.

In some examples, the material can be an acid degradable material (e.g.,nylon, etc.), a mix of acid degradable material (for example, nylonfibers mixed with particulate such as calcium carbonate), self-degradingmaterial (e.g., poly-lactic acid (PLA), poly-glycolic acid (PGA), etc.),material that degrades by galvanic action (such as, magnesium alloys,aluminum alloys, etc.), a combination of different self-degradingmaterials, or a combination of self-degrading and non-self-degradingmaterials.

Multiple materials can be pumped together or separately. For example,nylon and calcium carbonate could be pumped as a mixture, or the nyloncould be pumped first to initiate a seal, followed by calcium carbonateto enhance the seal.

In certain examples described below, the device can be made of knottedfibrous materials. Multiple knots can be used with any number of looseends. The ends can be frayed or un-frayed. The fibrous material can berope, fabric, metal wool, cloth or another woven or braided structure.

The device can be used to block open sleeve valves, perforations or anyleak paths in a well (such as, leaking connections in casing, corrosionholes, etc.). Any opening or passageway through which fluid flows can beblocked with a suitably configured device. For example, an intentionallyor inadvertently opened rupture disk, or another opening in a well tool,could be plugged using the device.

Previously described plugging devices can be used in the methodsdescribed herein, along with several different apparatuses and methodsfor deploying and placing the plugging devices at desired locationswithin the well. Descriptions of fibrous and/or degradable pluggingdevices are in US publication nos. 2016/0319628, 2016/0319630 and2016/0319631, and in International application nos. PCT/US15/38248(filed 29 Jun. 2015) and PCT/US16/29357 (filed 26 Apr. 2016). The entiredisclosures of these prior applications are incorporated herein by thisreference.

In one example method described below, a well with an existingperforated zone can be re-completed. Devices (either degradable ornon-degradable) are conveyed by flow to plug all existing perforations.

The well can then be re-completed using any desired completiontechnique. If the devices are degradable, a degrading treatment can thenbe placed in the well to open up the plugged perforations (if desired).

In another example method described below, multiple formation zones canbe perforated and fractured (or otherwise stimulated, such as, byacidizing) in a single trip of a bottom hole assembly into the well. Inthe method, one zone is perforated, the zone is stimulated, and then theperforated zone is plugged using one or more devices.

These steps are repeated for each additional zone, except that a lastzone may not be plugged. All of the plugged zones are eventuallyunplugged by waiting a certain period of time (if the devices areself-degrading), by applying an appropriate degrading treatment, or bymechanically removing the devices.

In another example, flow of fluid into previously fractured zones isblocked using flow conveyed plugging devices instead of a drillableplug. The plugging devices are carried into a wellbore via a tool in aperforating assembly. The plugging devices are then released in thewellbore. The method generally consists of the following steps:

-   -   1. Establish a flow path through the wellbore (for example, by        providing one or more openings at a “toe” or distal end of the        wellbore, e.g., via coiled tubing perforations, a pressure        operated toe valve, a wet shoe, etc.), so fluid can be pumped        through the wellbore, allowing the perforating assembly to be        pumped down the cased wellbore.    -   2. Pump the perforating assembly to above (less depth along the        wellbore) the topmost open perforations in the wellbore. The        perforating assembly includes (from bottom to top) a plugging        device dispensing tool, one or more perforators, a        controller/firing head, and a connector for a conveyance used to        convey the assembly into the wellbore.    -   3. Operate an actuator of the plugging device dispensing tool to        release the plugging devices into the wellbore above the topmost        open perforations. The actuator may be operated using various        techniques, such as, electrically, hydraulically, by pipe        manipulation, by applying set down weight, by igniting a        propellant, by detonating an explosive, etc.    -   4. Move the perforating assembly up hole to one or more        additional desired locations (to shallower depths along the        wellbore) and operate perforators to create perforations at the        one or more locations within the cased wellbore. If jointed or        coiled tubing is used to convey the perforating assembly, the        controller/firing head may be pressure actuated to detonate        explosive shaped charges of the perforator, or an abrasive jet        perforator may be used.    -   5. Retrieve the perforating assembly from the wellbore.    -   6. Perform fracturing operations to fracture the formation(s)        penetrated by the open perforations, and deliver sand slurry        (e.g., proppant) to fractured formation(s).    -   7. Pump “flush” of sand-free fluid from surface to push any        remaining sand out of the wellbore and into the fractured        formation(s) via the open perforations.    -   8. Repeat steps 2-7 until all desired zones are fractured.

The above method can also be used in conjunction with a conventional“plug and perf” technique, in which drillable bridge plugs are installedin a cased wellbore above previously fractured zone(s).

The plugging device dispensing tool used to convey the plugging devicesinto the wellbore can comprise a canister or other container which isloaded with plugging devices and conveyed into the well with theperforating assembly. Of course, any means of conveyance can be used toconvey the perforating assembly (for example, wireline, coiled tubing,jointed pipe, slickline, etc.).

Some suitable embodiments and methods for carrying plugging devices intothe wellbore are listed below. In addition, any of the methods anddispensing apparatuses described in US patent application publicationno. 2016/0348467 may be used. The entire disclosure of this priorapplication is incorporated herein by this reference for all purposes.

-   -   1. In one example, the plugging devices are dispensed using an        auger type element driven by an electric motor. In this example,        the number of devices dispensed is dependent on the run time and        speed of the electric motor, and a configuration of the auger.    -   2. In another example, the plugging devices are carried in a        tube with a frangible disk closing off a bottom of the tube. The        disk can be broken so that fluid pumped past the dispensing        tool, or upward movement of the dispensing tool, creates a        pressure differential to push the plugging devices out of the        tool. The disk can be broken using:        -   a. Pyrotechnic explosive (for instance a blasting cap or            detonator as used in dispensing tool 26).        -   b. Fluid pressure generated by the dispensing tool.        -   c. Mechanical impact caused by the dispensing tool.        -   d. Any other shock-inducing or cutting action.    -   3. In another example, the plugging device dispensing tool        comprises a canister or chamber having an initially closed        opening or valve which can be mechanically operated to an open        position. In the open position, the plugging devices are allowed        to exit from the canister or chamber. The plugging devices can        be forcibly discharged, or a pressure differential can be        generated across the canister/chamber by pumping fluid past the        tool, or the tool can be moved within the wellbore. The opening        can be anywhere on the tool, such as, at the bottom, or along a        side of the canister.    -   4. In another example, the plugging devices are dispensed in a        “slurry” which is pumped from the dispensing tool to the        wellbore using an electrically driven pump.    -   5. In another example, the plugging devices are initially        contained in a sack or bag, which is mechanically opened        downhole in response to applied pressure. A pressure        differential can be generated across the canister/chamber by        pumping fluid past the tool, or the tool can be moved within the        wellbore.    -   6. Some of the dispensing tool examples described above can be        adapted to use a standard bridge plug setting tool as the motive        means to operate the dispensing tool. This would allow widely        used, industry standard setting tools to be used with little or        no modification to operate the dispensing tool(s). In this case,        the plugging device dispensing tool will have a mechanical        interface which is practically identical to industry standard        drillable bridge plugs.

In another method, flow of fluid into previously fractured zones isblocked using flow conveyed plugging devices, instead of a drillablebridge plug. The plugging devices are pumped from the surface into thewellbore ahead of the perforating assembly, and as the perforatingassembly is being pumped through the wellbore.

The perforating assembly is stopped above open perforations that werefractured in a previous stage, or another opening that provides for flowthrough the wellbore. The plugging devices are pumped beyond theperforating assembly location and into the open perforations or otheropenings to block flow into the perforations or openings during the nextfracturing step. The method generally consists of the following steps:

-   -   1. Establish a flow path through the wellbore (for example, by        providing one or more openings at a “toe” or distal end of the        wellbore, e.g., via coiled tubing perforations, a pressure        operated toe valve, a wet shoe, etc.), so fluid can be pumped        through the wellbore, allowing the perforating assembly to be        pumped down the cased wellbore.    -   2. Pump plugging devices from surface into the wellbore slightly        ahead of the perforating assembly.    -   3. Pump perforating assembly to above the topmost open        perforations or other openings in the wellbore, while at the        same time pumping plugging devices just ahead of the perforating        assembly. The perforating assembly can include (from bottom to        top) one or more perforators, a controller/firing head, and a        connector for a conveyance used to convey the assembly into the        wellbore.    -   4. While holding the perforating assembly in place above the        open perforations or other openings, continue pumping the        plugging devices further into the wellbore until they land in        the open perforations or openings below the perforating assembly        and block further flow into the perforations or openings.    -   5. Move the perforating assembly up hole to one or more        additional desired locations (to shallower depths along the        wellbore) and operate perforators to create perforations at the        one or more locations within the cased wellbore. If jointed or        coiled tubing is used to convey the perforating assembly, the        controller/firing head may be pressure actuated to detonate        explosive shaped charges of the perforator, or an abrasive jet        perforator may be used.    -   6. Retrieve the perforating assembly from the wellbore.    -   7. Perform fracturing operations to fracture the formation(s)        penetrated by the open perforations, and deliver sand slurry        (e.g., proppant) to fractured formation(s).    -   8. Repeat steps 2-7 until all desired zones are fractured.

The above method can also be used in conjunction with a conventional“plug and perf” technique, in which drillable bridge plugs are installedin a cased wellbore above previously fractured zone(s).

After a wellbore is completed using any of the methods described herein,the plugging devices may be removed in any of a number of waysincluding:

-   -   a. Mechanical removal with a drilling assembly including a fluid        motor conveyed on tubing.    -   b. Mechanical removal with a gauge ring conveyed on tubing.    -   c. Mechanical removal with a drilling assembly rotated from        surface.    -   d. Chemical removal by applying a degrading treatment (such as        acid) “spotted” through tubing, or pumped from the surface.    -   e. Waiting a prescribed amount of time if self-degrading        plugging devices are used.

Note that none of the methods described herein are limited to hydraulicfracturing. They can also be applied to matrix treatments, such asmatrix acidizing (carbonate or sandstone formations), and damage removal(e.g., scale, mud filtrate) with acid or chelants. Any type ofstimulation treatment may be performed, instead of or in addition tofracturing, in keeping with the principles of this disclosure.

Representatively illustrated in FIG. 1 is a system 10 for use with awell, and an associated method, which can embody principles of thisdisclosure. However, it should be clearly understood that the system 10and method are merely one example of an application of the principles ofthis disclosure in practice, and a wide variety of other examples arepossible. Therefore, the scope of this disclosure is not limited at allto the details of the system 10 and method described herein and/ordepicted in the drawings.

In the FIG. 1 example, a wellbore 12 has been drilled so that itpenetrates an earth formation 14. The wellbore 12 is lined with casing16 and cement 18, although in other examples one or more sections of thewellbore may be uncased or open hole.

The wellbore 12 as depicted in FIG. 1 is generally horizontal, and a“toe” or distal end of the wellbore is to the right of the figure.However, in other examples, the wellbore 12 could be generally verticalor inclined relative to vertical.

As used herein, the terms “above,” “upward” and similar terms are usedto refer to a direction toward the earth's surface along the wellbore12, whether the wellbore is generally horizontal, vertical or inclined.Thus, in the FIG. 1 example, the upward direction is toward the left ofthe figure.

As depicted in FIG. 1, a set of perforations 20 a have been formedthrough the casing 16, cement 18 and into a zone 14 a of the formation14. The perforations 20 a provide for fluid communication between thezone 20 a and an interior of the casing 16. Such fluid communicationcould be otherwise provided, such as, by use of a sliding sleeve valve(not shown) or other openings or ports through the casing 16.

The perforations 20 a (or other openings) may be provided or formed inorder to establish such fluid communication, so that a flow path extendslongitudinally through the wellbore 12 and into the zone 14 a. In someexamples, the perforations 20 a may be formed primarily to enableproduction flow from the zone 14 a to the earth's surface via thewellbore 12.

The perforations 20 a may be formed using any suitable technique, suchas, perforating by explosive shaped charges or by discharge of anabrasive jet, or the perforations may exist in the casing 16 prior tothe casing being installed in the wellbore 12 (for example, a perforatedliner could be installed as part of the casing). Thus, the scope of thisdisclosure is not limited to any particular timing or technique forforming the perforations 20 a.

In some examples, openings other than perforations may be available inthe well for enabling fluid flow through the wellbore 12. Tools known tothose skilled in the art as a “wet shoe” or a “toe valve” can provideopenings at the distal end of the wellbore 12. Thus, the scope of thisdisclosure is not limited to any particular means of providing for fluidflow through the wellbore 12.

Note that it is not necessary in keeping with the principles of thisdisclosure for the perforations 20 a or other openings to be formed ator near a distal end of the wellbore 12, or for any other procedures orsteps described herein to be performed at or near a distal end of awellbore.

In the FIG. 1 example, a fluid flow 22 is established longitudinallythrough the wellbore 12, outward through the perforations 20 a and intothe zone 14 a. This fluid flow 22 is used to displace or “pump” aperforating assembly 24 through the wellbore 12. Note that the zone 14 amay have been treated (for example, by acidizing, fracturing, injectionof conformance agents, etc.) prior to establishing the fluid flow 22, orthe fluid flow could be part of treating the zone 14 a.

As depicted in FIG. 1, the perforating assembly 24 includes a pluggingdevice dispensing tool 26, two perforators 28, a firing head 30, and aconnector 32. The connector 32 is used to connect the perforatingassembly 24 to a conveyance 34, such as, a wireline, a slickline, coiledtubing or jointed tubing.

The dispensing tool 26 in this example includes a container 36 and anactuator 38. The container 36 contains the plugging devices (not visiblein FIG. 1, see FIG. 2), and the actuator 38 acts to release the pluggingdevices from the container in the wellbore 12. Any of the methods anddispensing apparatuses described in the US patent applicationpublication no. 2016/0348467 mentioned above may be used for thecontainer 36 and actuator 38.

The perforators 28 are depicted in FIG. 1 as being explosive shapedcharge perforating guns. Shaped charges in the perforating guns aredetonated by means of the firing head 30, which may be operated inresponse to a predetermined pressure, pressure pulse, acoustic,electric, hydraulic, optical or other type of signal.

Alternatively, the perforators 28 could comprise one or more abrasivejet perforators (for example, if the conveyance 34 is a coiled orjointed tubing). The scope of this disclosure is not limited to use ofany particular type of perforator.

The fluid flow 22 displaces the perforating assembly 24 through thewellbore 12 to a desired location. In this example, the desired locationis a position above the perforations 20 a. In other examples, gravity oranother source of a biasing force could be used to displace theperforating assembly 24 through the wellbore 12 (e.g., if the wellboreis vertical or inclined, or if a downhole tractor is used), and/or theperforating assembly may be displaced to another desired location.

Referring additionally now to FIG. 2, the system 10 and method arerepresentatively illustrated after the perforating assembly 24 has beendisplaced to the desired location above the open perforations 20 a, andthe dispensing tool 26 has been operated to release the plugging devices60 into the wellbore 12 above the perforations. The fluid flow 22displaces the plugging devices 60 through the wellbore 12 toward theopen perforations 20 a.

Any number of the plugging devices 60 may be released from the tool 26.In various examples, the number of plugging devices 60 released could beequal to, less than, or greater than, the number of open perforations 20a.

An equal number of open perforations 20 a and plugging devices 60 may beused if it is desired to plug all of the perforations and not haveexcess plugging devices remaining in the wellbore 12. A greater numberof plugging devices 60 may be used if it is desired to ensure that thereare more than an adequate number of plugging devices to plug all of theperforations 20 a. A fewer number of plugging devices 60 may be used ifit is desired to maintain a capability for flowing fluid downwardthrough the wellbore 12 after most of the perforations 20 a have beenplugged.

Referring additionally now to FIG. 3, the system 10 and method arerepresentatively illustrated after the plugging devices 60 havesealingly engaged and prevent fluid flow into the perforations 20 a. Theperforating assembly 24 has been raised in the wellbore 12 to anotherlocation where it is desired to perforate another zone 14 b of theformation 14, and perforations 20 b have been formed through the casing16 and cement 18 by the perforating assembly.

Fluid communication is now permitted between the zone 14 b and theinterior of the casing 16. Additional perforations may be formed atother locations along the wellbore 12 using the perforating assembly 24,if desired. The perforating assembly 24 can then be retrieved from thewellbore 12, and the zone 14 b (and any other perforated zone(s)) can betreated (for example, by fracturing, acidizing, injection of conformanceagents, etc.).

The steps described above and depicted in FIGS. 1-3 can be repeatedmultiple times, until all desired zones have been perforated andtreated. At that point, the plugging devices 60 can be degraded orotherwise removed from the perforations or other openings, so that fluidcommunication is permitted between the various zones and the interior ofthe casing 16.

Referring additionally now to FIG. 4A, an example of a flow conveyedplugging device 60 that can incorporate the principles of thisdisclosure is representatively illustrated. The device 60 may be usedfor any of the plugging devices in the method examples described herein,or the device may be used in other methods.

The device 60 example of FIG. 4A includes multiple fibers 62 extendingoutwardly from an enlarged body 64. As depicted in FIG. 4A, each of thefibers 62 has a lateral dimension (e.g., a thickness or diameter) thatis substantially smaller than a size (e.g., a thickness or diameter) ofthe body 64.

The body 64 can be dimensioned so that it will effectively engage andseal off a particular opening in a well. For example, if it is desiredfor the device 60 to seal off a perforation in a well, the body 64 canbe formed so that it is somewhat larger than a diameter of theperforation. If it is desired for multiple devices 60 to seal offmultiple openings having a variety of dimensions (such as holes causedby corrosion of the casing 16), then the bodies 64 of the devices can beformed with a corresponding variety of sizes.

In the FIG. 4A example, the fibers 62 are joined together (e.g., bybraiding, weaving, cabling, etc.) to form lines 66 that extend outwardlyfrom the body 64. In this example, there are two such lines 66, but anynumber of lines (including one) may be used in other examples.

The lines 66 may be in the form of one or more ropes, in which case thefibers 62 could comprise frayed ends of the rope(s). In addition, thebody 64 could be formed by one or more knots in the rope(s). In someexamples, the body 64 can comprise a fabric or cloth, the body could beformed by one or more knots in the fabric or cloth, and the fibers 62could extend from the fabric or cloth.

In other examples, the device 60 could comprise a single sheet ofmaterial, or multiple strips of sheet material. The device 60 couldcomprise one or more films. The body 64 and lines 66 may not be made ofthe same material, and the body and/or lines may not be made of afibrous material.

In the FIG. 4A example, the body 64 is formed by a double overhand knotin a rope, and ends of the rope are frayed, so that the fibers 62 aresplayed outward. In this manner, the fibers 62 will cause significantfluid drag when the device 60 is deployed into a flow stream, so thatthe device will be effectively “carried” by, and “follow,” the flow.

However, it should be clearly understood that other types of bodies andother types of fibers may be used in other examples. The body 64 couldhave other shapes, the body could be hollow or solid, and the body couldbe made up of one or multiple materials. The fibers 62 are notnecessarily joined by lines 66, and the fibers are not necessarilyformed by fraying ends of ropes or other lines. The body 64 is notnecessarily centrally located in the device 60 (for example, the bodycould be at one end of the lines 66). Thus, the scope of this disclosureis not limited to the construction, configuration or other details ofthe device 60 as described herein or depicted in the drawings.

Referring additionally now to FIG. 4B, another example of the device 60is representatively illustrated. In this example, the device 60 isformed using multiple braided lines 66 of the type known as “masontwine.” The multiple lines 66 are knotted (such as, with a double ortriple overhand knot or other type of knot) to form the body 64. Ends ofthe lines 66 are not necessarily frayed in these examples, although thelines do comprise fibers (such as the fibers 62 described above).

Referring additionally now to FIG. 5, another example of the device 60is representatively illustrated. In this example, four sets of thefibers 62 are joined by a corresponding number of lines 66 to the body64. The body 64 is formed by one or more knots in the lines 66.

FIG. 5 demonstrates that a variety of different configurations arepossible for the device 60. Accordingly, the principles of thisdisclosure can be incorporated into other configurations notspecifically described herein or depicted in the drawings. Such otherconfigurations may include fibers joined to bodies without use of lines,bodies formed by techniques other than knotting, etc.

Referring additionally now to FIGS. 6A & B, an example of a use of thedevice 60 of FIG. 4A to seal off an opening 68 in a well isrepresentatively illustrated. In this example, the opening 68 is aperforation formed through a sidewall 70 of a tubular string 72 (suchas, a casing, liner, tubing, etc.). However, in other examples theopening 68 could be another type of opening, and may be formed inanother type of structure.

The device 60 is deployed into the tubular string 72 and is conveyedthrough the tubular string by fluid flow 74. The fibers 62 of the device60 enhance fluid drag on the device, so that the device is influenced todisplace with the flow 74.

The fluid flow 74 may be the same as, or similar to, the fluid flow 22described above for the example of FIGS. 1-3. However, the fluid flow 74could be another type of fluid flow, in keeping with the principles ofthis disclosure.

Since the flow 74 (or a portion thereof) exits the tubular string 72 viathe opening 68, the device 60 will be influenced by the fluid drag toalso exit the tubular string via the opening 68. As depicted in FIG. 6B,one set of the fibers 62 first enters the opening 68, and the body 64follows. However, the body 64 is appropriately dimensioned, so that itdoes not pass through the opening 68, but instead is lodged or wedgedinto the opening. In some examples, the body 64 may be received onlypartially in the opening 68, and in other examples the body may beentirely received in the opening.

The body 64 may completely or only partially block the flow 74 throughthe opening 68. If the body 64 only partially blocks the flow 74, anyremaining fibers 62 exposed to the flow in the tubular string 72 can becarried by that flow into any gaps between the body and the opening 68,so that a combination of the body and the fibers completely blocks flowthrough the opening.

In another example, the device 60 may partially block flow through theopening 68, and another material (such as, calcium carbonate,poly-lactic acid (PLA) or poly-glycolic acid (PGA) particles) may bedeployed and conveyed by the flow 74 into any gaps between the deviceand the opening, so that a combination of the device and the materialcompletely blocks flow through the opening.

The device 60 may permanently prevent flow through the opening 68, orthe device may degrade to eventually permit flow through the opening. Ifthe device 60 degrades, it may be self-degrading, or it may be degradedin response to any of a variety of different stimuli. Any technique ormeans for degrading the device 60 (and any other material used inconjunction with the device to block flow through the opening 68) may beused in keeping with the scope of this disclosure.

In other examples, the device 60 may be mechanically removed from theopening 68. For example, if the body 64 only partially enters theopening 68, a mill or other cutting device may be used to cut the bodyfrom the opening.

Referring additionally now to FIGS. 7-9, additional examples of thedevice 60 are representatively illustrated. In these examples, thedevice 60 is surrounded by, encapsulated in, molded in, or otherwiseretained by, a retainer 80.

The retainer 80 aids in deployment of the device 60, particularly insituations where multiple devices are to be deployed simultaneously. Insuch situations, the retainer 80 for each device 60 prevents the fibers62 and/or lines 66 from becoming entangled with the fibers and/or linesof other devices.

The retainer 80 could in some examples completely enclose the device 60.In other examples, the retainer 80 could be in the form of a binder thatholds the fibers 62 and/or lines 66 together, so that they do not becomeentangled with those of other devices.

In some examples, the retainer 80 could have a cavity therein, with thedevice 60 (or only the fibers 62 and/or lines 66) being contained in thecavity. In other examples, the retainer 80 could be molded about thedevice 60 (or only the fibers 62 and/or lines 66).

During or after deployment of the device 60 into the well, the retainer80 dissolves, melts, disperses or otherwise degrades, so that the deviceis capable of sealing off an opening 68 in the well, as described above.For example, the retainer 80 can be made of a material 82 that degradesin a wellbore environment.

The retainer material 82 may degrade after deployment into the well, butbefore arrival of the device 60 at the opening 68 to be plugged. Inother examples, the retainer material 82 may degrade at or after arrivalof the device 60 at the opening 68 to be plugged. If the device 60 alsocomprises a degradable material, then preferably the retainer material82 degrades prior to the device material.

The material 82 could, in some examples, melt at elevated wellboretemperatures. The material 82 could be chosen to have a melting pointthat is between a temperature at the earth's surface and a temperatureat the opening 68, so that the material melts during transport from thesurface to the downhole location of the opening.

The material 82 could, in some examples, dissolve when exposed towellbore fluid. The material 82 could be chosen so that the materialbegins dissolving as soon as it is deployed into the wellbore 14 andcontacts a certain fluid (such as, water, brine, hydrocarbon fluid,etc.) therein. In other examples, the fluid that initiates dissolving ofthe material 82 could have a certain pH range that causes the materialto dissolve.

Note that it is not necessary for the material 82 to melt or dissolve inthe well. Various other stimuli (such as, passage of time, elevatedpressure, flow, turbulence, etc.) could cause the material 82 todisperse, degrade or otherwise cease to retain the device 60. Thematerial 82 could degrade in response to any one, or a combination, of:passage of a predetermined period of time in the well, exposure to apredetermined temperature in the well, exposure to a predetermined fluidin the well, exposure to radiation in the well and exposure to apredetermined chemical composition in the well. Thus, the scope of thisdisclosure is not limited to any particular stimulus or technique fordispersing or degrading the material 82, or to any particular type ofmaterial.

In some examples, the material 82 can remain on the device 60, at leastpartially, when the device engages the opening 68. For example, thematerial 82 could continue to cover the body 64 (at least partially)when the body engages and seals off the opening 68. In such examples,the material 82 could advantageously comprise a relatively soft, viscousand/or resilient material, so that sealing between the device 60 and theopening 68 is enhanced.

Suitable relatively low melting point substances that may be used forthe material 82 can include wax (e.g., paraffin wax, vegetable wax),ethylene-vinyl acetate copolymer (e.g., ELVAX™ available from DuPont),atactic polypropylene, and eutectic alloys. Suitable relatively softsubstances that may be used for the material 82 can include a softsilicone composition or a viscous liquid or gel.

Suitable dissolvable materials can include PLA, PGA, anhydrous boroncompounds (such as anhydrous boric oxide and anhydrous sodium borate),polyvinyl alcohol, polyethylene oxide, salts and carbonates. Thedissolution rate of a water-soluble polymer (e.g., polyvinyl alcohol,polyethylene oxide) can be increased by incorporating a water-solubleplasticizer (e.g., glycerin), or a rapidly-dissolving salt (e.g., sodiumchloride, potassium chloride), or both a plasticizer and a salt.

In FIG. 7, the retainer 80 is in a cylindrical form. The device 60 isencapsulated in, or molded in, the retainer material 82. The fibers 62and lines 66 are, thus, prevented from becoming entwined with the fibersand lines of any other devices 60.

In FIG. 8, the retainer 80 is in a spherical form. In addition, thedevice 60 is compacted, and its compacted shape is retained by theretainer material 82. A shape of the retainer 80 can be chosen asappropriate for a particular device 60 shape, in compacted orun-compacted form.

In FIG. 9, the retainer 80 is in a cubic form. Thus, any type of shape(polyhedron, spherical, cylindrical, etc.) may be used for the retainer80, in keeping with the principles of this disclosure.

Referring additionally now to FIG. 10, a cross-sectional view of anotherexample of the device 60 is representatively illustrated. The device 60may be used in any of the systems and methods described herein, or maybe used in other systems and methods.

In this example, the body of the device 60 is made up of filaments orfibers 62 formed in the shape of a ball or sphere. Of course, othershapes may be used, if desired.

The filaments or fibers 62 may make up all, or substantially all, of thedevice 60. The fibers 62 may be randomly oriented, or they may bearranged in various orientations as desired.

In the FIG. 10 example, the fibers 62 are retained by the dissolvable,degradable or dispersible material 82. In addition, a frangible coatingmay be provided on the device 60, for example, in order to delaydissolving of the material 82 until the device has been deployed into awell. Examples of suitable frangible coatings include cementitiousmaterials (e.g., plaster of Paris) and various waxes (e.g., paraffinwax, carnauba wax, vegetable wax, machinable wax). The frangible natureof a wax coating can be optimized for particular conditions by blendinga less brittle wax (e.g., paraffin wax) with a more brittle wax (e.g.,carnauba wax) in a certain ratio selected for the particular conditions.

The device 60 of FIG. 10 can be used in a diversion fracturing operation(in which perforations receiving the most fluid are plugged to divertfluid flow to other perforations), in a re-completion operation, or in amultiple zone perforate and treat operation.

One advantage of the FIG. 10 device 60 is that it is capable of sealingon irregularly shaped openings, perforations, leak paths or otherpassageways. The device 60 can also tend to “stick” or adhere to anopening, for example, due to engagement between the fibers 62 andstructure surrounding (and in) the opening. In addition, there is anability to selectively seal openings.

The fibers 62 could, in some examples, comprise wool fibers. The device60 may be reinforced (e.g., using the material 82 or another material)or may be made entirely of fibrous material with a substantial portionof the fibers 62 randomly oriented.

The fibers 62 could, in some examples, comprise metal wool, or crumpledand/or compressed wire. Wool may be retained with wax or other material(such as the material 82) to form a ball, sphere, cylinder or othershape.

In the FIG. 10 example, the material 82 can comprise a wax (or eutecticmetal or other material) that melts at a selected predeterminedtemperature. A wax device 60 may be reinforced with fibers 62, so thatthe fibers and the wax (material 82) act together to block a perforationor other passageway.

The selected melting point can be slightly below a static wellboretemperature. The wellbore temperature during fracturing or otherstimulation treatment is typically depressed due to relatively lowtemperature fluids entering wellbore. After treatment, wellboretemperature will typically increase, thereby melting the wax andreleasing the reinforcement fibers 62.

A drag coefficient of the device 60 in any of the examples describedherein may be modified appropriately to produce a desired result. Forexample, in a diversion fracturing operation, it is typically desirableto block perforations in a certain location in a wellbore. The locationis usually at the perforations taking the most fluid.

Natural fractures in an earth formation penetrated by the wellbore makeit so that certain perforations receive a larger portion of treatmentfluids. For these situations and others, the device 60 shape, size,density and other characteristics can be selected, so that the devicetends to be conveyed by flow to a certain corresponding section of thewellbore.

For example, devices 60 with a larger coefficient of drag (Cd) may tendto seat more toward a toe of a generally horizontal or lateral wellbore.Devices 60 with a smaller Cd may tend to seat more toward a heel of thewellbore.

Smaller devices 60 with long fibers 62 floating freely (see the exampleof FIG. 11) may have a strong tendency to seat at or near the heel. Adiameter of the device 60 and the free fiber 62 length can beappropriately selected, so that the device is more suited to stoppingand sealingly engaging perforations anywhere along the length of thewellbore.

Acid treating operations can benefit from use of the device 60 examplesdescribed herein. Pumping friction causes hydraulic pressure at the heelto be considerably higher than at the toe. This means that the fluidvolume pumped into a formation at the heel will be considerably higherthan at the toe. Turbulent fluid flow increases this effect. Gellingadditives might reduce an onset of turbulence and decrease the magnitudeof the pressure drop along the length of the wellbore.

Higher initial pressure at the heel allows zones to be treated and thenplugged starting at the heel, and then progressively down along thewellbore. This mitigates waste of acid from attempting to acidize all ofthe zones at the same time.

The free fibers 62 of the FIGS. 4-6B & 11 examples greatly increase theability of the device 60 to engage the first open perforation (or otherleak path) it encounters. Thus, the devices 60 with low Cd and longfibers 62 can be used to plug from upper perforations to lowerperforations, while turbulent acid with high frictional pressure drop isused so that the acid treats the unplugged perforations nearest the topof the wellbore with acid first.

In examples of the device 60 where a wax material (such as the material82) is used, the fibers 62 (including the body 64, lines 66, knots,etc.) may be treated with a treatment fluid that repels wax (e.g.,during a molding process). This may be useful for releasing the wax fromthe fibrous material after fracturing or otherwise compromising theretainer 80 and/or a frangible coating thereon.

Suitable release agents are water-wetting surfactants (e.g., alkyl ethersulfates, high hydrophilic-lipophilic balance (HLB) nonionicsurfactants, betaines, alkyarylsulfonates, alkyldiphenyl ethersulfonates, alkyl sulfates). The release fluid may also comprise abinder to maintain the knot or body 64 in a shape suitable for molding.One example of a binder is a polyvinyl acetate emulsion.

Broken-up or fractured devices 60 can have lower Cd. Broken-up orfractured devices 60 can have smaller cross-sections and can passthrough restrictions in the well more readily.

A restriction may be connected in any line or pipe that the devices 60are pumped through, in order to cause the devices to fracture as theypass through the restriction. This may be used to break up and separatedevices 60 into wax and non-wax parts. The restriction may also be usedfor rupturing a frangible coating covering a soluble wax material 82 toallow water or other well fluids to dissolve the wax.

Fibers 62 may extend outwardly from the device 60, whether or not thebody 64 or other main structure of the device also comprises fibers. Forexample, a ball (or other shape) made of any material could have fibers62 attached to and extending outwardly therefrom. Such a device 60 willbe better able to find and cling to openings, holes, perforations orother leak paths near the heel of the wellbore, as compared to the ball(or other shape) without the fibers 62.

For any of the device 60 examples described herein, the fibers 62 maynot dissolve, disperse or otherwise degrade in the well. In suchsituations, the devices 60 (or at least the fibers 62) may be removedfrom the well by swabbing, scraping, circulating, milling or othermechanical methods.

In situations where it is desired for the fibers 62 to dissolve,disperse or otherwise degrade in the well, nylon is a suitable acidsoluble material for the fibers. Nylon 6 and nylon 66 are acid solubleand suitable for use in the device 60. At relatively low welltemperatures, nylon 6 may be preferred over nylon 66, because nylon 6dissolves faster or more readily.

Self-degrading fiber devices 60 can be prepared from poly-lactic acid(PLA), poly-glycolic acid (PGA), or a combination of PLA and PGA fibers62. Such fibers 62 may be used in any of the device 60 examplesdescribed herein.

Fibers 62 can be continuous monofilament or multifilament, or choppedfiber. Chopped fibers 62 can be carded and twisted into yarn that can beused to prepare fibrous flow conveyed devices 60.

PLA and/or PGA fibers 62 may be coated with a protective material, suchas calcium stearate, to slow its reaction with water and thereby delaydegradation of the device 60. Different combinations of PLA and PGAmaterials may be used to achieve corresponding different degradationtimes or other characteristics.

PLA resin can be spun into fiber of 1-15 denier, for example. Smallerdiameter fibers 62 will degrade faster. Fiber denier of less than 5 maybe most desirable. PLA resin is commercially available with a range ofmelting points (e.g., 140 to 365° F.). Fibers 62 spun from lower meltingpoint PLA resin can degrade faster.

PLA bi-component fiber has a core of high-melting point PLA resin and asheath of low-melting point PLA resin (e.g., 140° F. melting pointsheath on a 265° F. melting point core). The low-melting point resin canhydrolyze more rapidly and generate acid that will acceleratedegradation of the high-melting point core. This may enable thepreparation of a plugging device 60 that will have higher strength in awellbore environment, yet still degrade in a reasonable time. In variousexamples, a melting point of the resin can decrease in a radiallyoutward direction in the fiber.

Referring additionally now to FIGS. 12A-14, another example of thedispensing tool 26 is representatively illustrated. This dispensing tool26 example may be used with the system 10 and method of FIGS. 1-3, or itmay be used with other systems and methods.

The dispensing tool 26 of FIGS. 12A-14 may be conveyed by a variety ofdifferent conveyances, such as, wireline, coiled tubing, etc. In thefollowing description of the FIGS. 12A-14 dispensing tool 26 example,the dispensing tool is used to place plugging devices 60 in a wellbore.The dispensing tool 26 can also be used to place other materials orchemicals.

In one operational example, the dispensing tool 26 may be run with andbelow wireline or coiled tubing-conveyed perforating guns or perforators28 as a part of a perforating assembly 24 in a fracturing operation.After a stage is fractured, the perforators 28 and the dispensing tool26 are run downhole just above the fractured zone. The plugging devices60 are dumped prior to firing the perforators 28. When fracturing beginsagain, the plugging devices 60 shut off the perforations 20 a that havejust been fractured to force the fracturing fluid into the newly formedperforations 20 b.

The dispensing tool 26 example is shown in an initial run-inconfiguration in FIG. 12A. Plugging devices 60 are located in anenclosure 84 (such as, a flexible sack or bag) in a lower part of thetool 26.

A viscous substance 86 may be placed in the enclosure 84 with theplugging devices 60 to help keep the plugging devices 60 from settlingor entangling during storage, shipment, and displacement in the wellbore12. A lower end of the enclosure 84 is secured to the container 36, forexample, using a fastener 78.

There is a radially enlarged boss 88 located below ports 90 of a slidingsleeve valve 92. The boss 88 is used to restrict flow through an annulusformed radially between the casing 16 and the tool 26, to allow the toolto be pumped down with the wireline, coiled tubing or other conveyance34. The boss 88 restricts flow through the casing 16, and also helpsdirect fluid flow 74 into the sliding sleeve valve ports 90 and throughthe tool 26 when the tool is operated to dispense the plugging devices60.

The dispensing tool 26 can be operated with the actuator 38 describedabove, or with a conventional packer setting tool, such as a Bakernumber 10 setting tool. A packer setting tool (not shown) typicallyoperates by retracting a mandrel several inches while restrictingdisplacement of an outer housing.

A mandrel of the setting tool can be threaded to a mandrel 94 of thetool 26. A setting tool adapter 96 can be threaded to the body or outerhousing of the setting tool. When the setting tool is actuated, thedispensing tool mandrel 94 is pulled upward (to the left as depicted inFIG. 12A) relative to the setting tool adapter 96.

The setting tool mandrel is typically free to float upward prior toactuation of the setting tool. To prevent accidental operation of thedispensing tool 26, shear pins 100 lock the mandrel 94 in an extendedposition relative to the setting tool. When the setting tool isactuated, the shear pins 100 shear to allow the dispensing tool mandrel94 to displace upward.

The upward movement of the mandrel 94 causes a closure member or innersleeve 98 of the sliding sleeve valve 92 to shift upward. This upwarddisplacement of the sleeve 98 shears pins 100 and opens a lower end ofthe enclosure 84.

In FIG. 12B, the dispensing tool 26 is representatively illustrated inan open configuration. Ports 90 are opened when the sleeve 98 shiftsupward. The open ports 90 provide for fluid communication between anexterior of the dispensing tool 26 (e.g., the annulus between the tool26 and the casing 16) and an interior flow passage 102 extending througha lower end of the sleeve 98 and into the enclosure 84.

An upper end of the enclosure 84 is attached to the sleeve 98. Thus,when the sleeve 98 displaces upward, the upper end of the enclosure 84also displaces upward, thereby tearing open the lower end of theenclosure. The lower end of the enclosure 84 is, thus, pierced, cut oropened, allowing the plugging devices 60 to displace out of theenclosure 84. A cutter 104 may be mounted in the container 36 forfacilitating opening of the enclosure 84 lower end.

As used herein, the term “pierce” is used in the sense of forming anopening through a material, such as, by cutting, tearing, penetrating orperforating.

Only a portion of the flow 74 passes though the flow passage 102 afterthe valve 92 has been opened. Part of the flow 74 passes around the boss88. This split flow 74 helps separate the plugging devices 60, which isbeneficial to conveying the plugging devices 60 to the perforations 20a,b or other openings 68 to be plugged.

FIG. 13 shows details of an example of the plugging device enclosure 84.The enclosure 84 includes a flexible material 106 that can beconveniently opened downhole, and is compatible with well environments.TYVEK™, available from E.I. DuPont de Nemours of Wilmington, Del. USA,is suitable for use as the material 106, but any wellbore compatiblematerial may be used instead, or in addition.

As mentioned above, a screw or other fastener 78 (see FIGS. 12A & B) canbe used to fasten the lower end of the enclosure 84 to the container 36,the boss 88 or another component of the tool 26. The lower end of theenclosure 84 can be folded and retained closed with a grommet 108. Thefastener 78 can extend through the grommet 108 to secure the lower endof the enclosure 84.

The lower end of the enclosure 84 may have perforations or otherweakening means to cause it to be torn or pierced in an appropriateplace. The perforations may not be necessary, since the folded end canbe inherently weaker and will tear off at an upper end of the folds.

The upper end of the enclosure 84 is attached to the valve inner sleeve98. When the inner sleeve 98 moves up, tension in the enclosure 84causes the lower end of the enclosure to tear off, thereby opening thelower end.

In the FIG. 13 example, there is an o-ring or other ring-shaped element110 located at the upper end of the enclosure 84. The material 106 iswrapped about the element 110 and secured with stitches 112. Thiscreates an enlarged thickness at the upper end of the enclosure 84. Thisenlarged thickness and the ring-shaped element 110 therein can becaptured and attached to the lower end of the sliding sleeve valve innersleeve 98, as described more fully below.

In this example, an elastomeric o-ring is used for the ring-shapedelement 110. Depending on their composition, o-rings are usuallyrelatively inexpensive, stiff (resistant to deflection), and resilient(having elasticity). In other examples, the enclosure material 106 couldbe folded and sewn to accomplish a similar enlarged thickness at theupper end of the enclosure 84 (without use of the separate element 110).

FIG. 14 depicts an example of the attachment of the upper end of theenclosure 84 to the lower end of the inner sleeve 98. The enlargedthickness upper end of the enclosure 84 is positioned in a recess 116formed on the lower end of the inner sleeve 98.

A split ring 114 secures the upper end of the enclosure 84 againstlongitudinal displacement relative to the sleeve 98 and recess 116. Aretainer ring 118 prevents displacement of the upper end of theenclosure 84 radially out of the recess 116. A spiral lock ring 120secures the retainer ring 118 (and, thereby, the split ring 114 and theupper end of the enclosure 84) on the inner sleeve 98.

An example operation of the dispensing tool 26 of FIGS. 12A-14 may be asfollows when used with the system 10 of FIGS. 1-3:

-   -   Stop pumping fracturing fluids after a first zone 20 a is        fractured;    -   Run tool 26 downhole below perforators 28 in the perforating        assembly 24;    -   Locate tool 26 above previously fractured zone 20 a;    -   Actuate packer setting tool or actuator 38;    -   Pump fluid to displace plugging devices 60 out of dispensing        tool 26 with fluid flow 22;    -   Pull up to next zone 20 b position;    -   Fire perforators 28;    -   Retrieve perforating assembly 24 from wellbore.

It may be desirable to prevent plugging devices 60 from entangling inthe enclosure 84 prior to operation of the dispensing tool 26. Toprevent the plugging devices 60 from forming a dense pack and/ortangling with each other, they can be suspended in the substance 86(such as, a gel) within the enclosure 84. Suitable gelling agentsinclude crosslinked polyacrylate powder (e.g., Carbopol 941), xanthangum, polyvinyl alcohol, and mixtures of locust bean gum and guar gum.

The plugging devices 60 may comprise a covering of a dry gelling agentthat hydrates due to contact with well fluid after the dispensing tool26 is introduced into the well.

In any of the examples described herein, appropriate materials can beselected to construct plugging devices 60 with controllable lifetimes invarious downhole environments. Plugging device diversion can be used ina variety of well stimulation and remedial treatments to control theplacement of fluid along a length of a perforated zone.

For a typical new well completion with “plug and perf” techniques,plugging devices 60 that do not self-degrade can be used, because theplugging devices 60 can be removed during a plug-milling operation afterthe fracturing operation. However, if dissolvable or otherwisedegradable plugs are used, self-degrading plugging devices 60 can bedesired, so that no subsequent coiled-tubing run or other interventionis necessary to remove the plugging devices.

Self-degrading plugging devices 60 are also beneficial for re-fracturingof older wells, where a coiled-tubing run may not be made after thetreatment. For damage removal in older wells, acid-resistant pluggingdevices 60 may be needed, due to long contact times with hydrochloricacid. High-temperature wells may utilize plugging devices 60 made fromfiber that will withstand elevated temperature longer that commonfibers, such as nylon 6 or polyester.

All of the materials for making plugging devices 60 described in thisdisclosure can be in the form of staple fiber or filament that is formedinto yarn. The yarn can be then twisted or braided into cord or rope, ortwisted into a larger yarn that can be used directly to make pluggingdevices 60.

Use of staple fiber (e.g., chopped fiber) typically involves additionalpreliminary steps of carding and one or more drawing steps beforespinning into yarn. Open end spinning, ring spinning, and air jetspinning can be used to form the basic yarn from staple fiber. Open endspinning may be preferable, because it typically uses fewer drawingsteps than the other spinning techniques, and a heavier yarn (e.g.,thread count <4) can be made.

Multiple yarns can be twisted together to prepare plied yarn (e.g., 10ply or 12 ply) that can be used to make plugging devices 60. As analternative to plied yarns, DREF spinning (friction spinning), can beused to make a large-diameter yarn without a subsequent plying step.DREF spinning typically uses a monofilament as a base for the staplefiber to form around.

Staple fiber of thermoplastic polymers (e.g., nylon, polyester,polylactic acid, etc.) can be prepared by melt spinning. Polymers notamenable to melt spinning (e.g., rayon, polyaramid, acrylic,polybenzimidazole) may be dissolved in solvent and spun in either a wetor dry process for solvent removal. After spinning, drawing, crimping,and chopping steps produce a staple fiber that can be used in theyarn-spinning process.

Multiple different polymers can be spun into a single, multi-componentfiber. Various core-sheath cross sections are possible (e.g., singlecore, concentric or eccentric cross section; multiple core, “islands inthe sea” cross section; segmented pie cross section). Multi-componentfiber in this application can be used to prepare a fiber that hassufficient strength, while degrading in a reasonable time in downholeenvironments. A single component fiber that rapidly degrades may nothave sufficient mechanical properties on the time scale of the welltreatment. Conversely, a mono-component fiber with adequate mechanicalproperties may degrade too slowly to be useful.

Polylactic acid (PLA) degradability is related to the degree ofcrystallinity and melting point of the polymer. For example,poly(L-lactic acid) is more crystalline and degrades slower thanpoly(D-lactic acid-co-L-lactic acid). In one example, these two types ofPLA can be used together in a bi-component fiber to adjust thedegradation rate over a wide temperature range.

In addition to the lower crystallinity PLA degrading faster, acidproduced by the hydrolysis will accelerate the degradation of thehigher-crystallinity PLA. The lower crystallinity PLA can be used as thesheath (as in fiber made for nonwoven cloth applications), or as thecore.

To further expand the usable temperature range available with PLA, othercombinations of polymers can be used. Potentially useful polymersinclude poly(glycolic acid), poly(lactic acid-co-glycolic acid),poly(paradioxanone), poly(ε-caprolactone), poly(L-lacticacid-co-ε-caprolactone), poly(L-lactic acid-co-trimethylene carbonate),poly(ε-caprolactone-co-glycolic acid-co-trimethylene carbonate),polybutylene succinate, poly(3-hydroxybutyrate-co-3-hydroxyvalerate),poly(L-lactic acid-block-ethylene glycol), and polyethyleneterephthalate. In all of these examples, the acid produced by thefaster-degrading polymer can accelerate the degradation of the morestable polymer.

Polyester hydrolysis is catalyzed by both acids and bases, butbase-catalyzed hydrolysis is much faster. For low temperature wellswhere the desired degradation rate cannot be achieved by the spontaneoushydrolysis of the polyester, the degradation rate can be increased byadding a base or base precursor to the polymer before spinning thefiber, or by coating the fiber. Alkaline earth oxides and hydroxides,(e.g., calcium oxide, magnesium oxide, calcium hydroxide, magnesiumhydroxide), zinc oxide, sodium tetraborate, calcium carbonate,hexamethylenetetramine, and urea could be used for this purpose.

Combinations of water-soluble polymer and degradable polymer can be usedto make bi-component fibers with higher degradation rates thansingle-component fibers made from a degradable polymer. The degradablepolymers listed above can be used in combination with variouswater-soluble polymers, including polyethylene oxide, polyvinyl acetate,polyvinyl alcohol, methacrylic acid copolymers, copolymers of2-ethylhexyl acrylate and dimethylaminoethyl methacrylate, andsulfopolyesters.

For sealing perforations in high-temperature wells (e.g., >300° F.),fibers made from common polymers, such as nylon-6 and polyethyleneterephthalate, may degrade too rapidly. In high-temperature wells,plugging devices 60 made with fibers comprising hydrolysis-resistantmaterials could be used.

Potentially suitable materials for use in high-temperature wells includecarbon fiber, glass fiber, mineral fiber, ceramic fiber, meta-aramidfiber (e.g., Nomex), para-aramid fiber (e.g., Kevlar), polyacrylonitrilefiber (e.g., Orlon, acrylic, modacrylic), polyparaphenylene sulfidefiber (e.g., Ryton), polybenzanilide, polybenzimidazole fiber (e.g.,PBI), polyethylene terephthalate, and fibers made from copolymers andblends. Natural fibers suitable for high temperature include cotton,flax, hemp, sisal, jute, kenaf and coir.

It may now be fully appreciated that the above disclosure providessignificant advancements to the art of controlling flow in subterraneanwells. In some examples described above, the plugging devices 60 may bedispensed from a dispensing tool 26 (in some cases included in aperforating assembly 24). The dispensing tool 26 can include anenclosure 84 that is cut or torn open to release the plugging devices60.

A well completion method, system and apparatus are described above, inwhich plugging devices 60 are released from a container 36 in a wellbore12. The plugging devices 60 may be released to plug existingperforations 20 a. The plugging devices 60 may be released prior toforming additional perforations 20 b and fracturing through theadditional perforations.

A well completion method, system and apparatus are described above, inwhich plugging devices 60 are released into a wellbore 12 ahead of aperforating assembly 24. The plugging devices 60 and the perforatingassembly 24 may be pumped simultaneously through the wellbore 12.

The plugging devices 60 may plug perforations 20 a existing before theperforating assembly 24 is introduced into the wellbore 12. The pluggingdevices 60 may plug perforations 20 b made by the perforating assembly24.

The plugging devices 60 may comprise a fibrous material, a degradablematerial, and/or a material selected from nylon, poly-lactic acid,poly-glycolic acid, poly-vinyl alcohol, poly-vinyl acetate andpoly-methacrylic acid.

The plugging devices 60 may comprise a knot. The plugging devices 60 maycomprise a fibrous material retained by a degradable retainer 80.

A plugging device dispensing tool 26 and method are described above anddepicted in the drawings. The plugging devices 60 are disposed within anenclosure 84 of the dispensing tool 26. The enclosure 84 is torn opendownhole to release the plugging devices 60 into the wellbore 12.

The enclosure 84 may be torn open in response to actuation of a valve92. Actuation of the valve 92 may open a flow passage 102 for fluid flow74 through the dispensing tool 26.

The enclosure 84 may be torn open by actuation of a setting tool orother actuator 38 connected to the dispensing tool 26. The settingtool/actuator 38 may displace an inner mandrel 94 of the dispensing tool26.

A staple fiber or filament 62 may be formed into yarn. The yarn may betwisted or braided into cord or rope, or twisted into a larger yarn thatis used to make the plugging device 60.

Multiple different polymers may be spun into a single, multi-componentfiber 62. The different polymers may have different degrees ofcrystallinity and melting points.

The polymers may comprise poly(L-lactic acid), poly(D-lacticacid-co-L-lactic acid), poly(glycolic acid), poly(lacticacid-co-glycolic acid), poly(paradioxanone), poly(ε-caprolactone),poly(L-lactic acid-co-ε-caprolactone), poly(L-lacticacid-co-trimethylene carbonate), poly(ε-caprolactone-co-glycolicacid-co-trimethylene carbonate), polybutylene succinate,poly(3-hydroxybutyrate-co-3-hydroxyvalerate), poly(L-lacticacid-block-ethylene glycol), and/or polyethylene terephthalate. In allof these examples, an acid produced by the faster-degrading polymer canaccelerate the degradation of the more stable polymer.

A degradation rate of a polymer may be increased by adding a base orbase precursor to the polymer before spinning the fiber, or by coatingthe fiber. Alkaline earth oxides and hydroxides, (e.g., calcium oxide,magnesium oxide, calcium hydroxide, magnesium hydroxide), zinc oxide,sodium tetraborate, calcium carbonate, hexamethylenetetramine, and ureaare optionally used for this purpose.

The plugging device 60 and method can include combinations ofwater-soluble polymer and degradable polymer used to make bi-componentfibers 62 with higher degradation rates than single-component fibersmade from a degradable polymer. The degradable polymers listed above canbe used in combination with various water-soluble polymers, includingpolyethylene oxide, polyvinyl acetate, polyvinyl alcohol, methacrylicacid copolymers, copolymers of 2-ethylhexyl acrylate anddimethylaminoethyl methacrylate, and sulfopolyesters.

The plugging device 60 and method can include use ofhydrolysis-resistant materials. Potentially suitable materials for usein high-temperature wells include carbon fiber, glass fiber, mineralfiber, ceramic fiber, meta-aramid fiber (e.g., Nomex™, para-aramid fiber(e.g., Kevlar™, polyacrylonitrile fiber (e.g., Orlon™, acrylic,modacrylic), polyparaphenylene sulfide fiber (e.g., Ryton™,polybenzanilide, polybenzimidazole fiber (e.g., PBI), polyethyleneterephthalate, and fibers made from copolymers and blends. Naturalfibers suitable for high temperature include cotton, flax, hemp, sisal,jute, kenaf and coir.

A method of deploying plugging devices 60 in a wellbore 12 is providedto the art by the above disclosure. In one example, the method cancomprise: conveying a dispensing tool 26 through the wellbore 12, thedispensing tool 26 including an enclosure 84 containing the pluggingdevices 60; and then opening the enclosure 84 by piercing a material 106of the enclosure 84, thereby releasing the plugging devices 60 from theenclosure 84 into the wellbore 12 at a downhole location.

The piercing step may include tearing, opening and/or cutting thematerial 106 of the enclosure 84.

The opening step may include displacing one end of the enclosure 84relative to an opposite end of the enclosure 84. The displacing step mayinclude displacing a member of a valve 92. The valve 92 member maycomprise an inner sleeve 98 that selectively blocks flow through atleast one port 90 of the valve 92.

The releasing step may include producing fluid flow 74 through a flowpassage 102 in communication with an interior of the enclosure 84. Theopening step may include opening a valve 92, thereby permitting thefluid flow 74 from an exterior of the dispensing tool 26 to the flowpassage 102.

The opening step may include operating an actuator 38 of the dispensingtool 26.

The method may include connecting the dispensing tool 26 and aperforator 28 in a perforating assembly 24.

A dispensing tool 26 for dispensing plugging devices 60 into asubterranean well is also provided by the above disclosure. In oneexample, the dispensing tool 26 can comprise a container 36 having anenclosure 84 therein, the enclosure 84 including a flexible material 106that contains the plugging devices 60, and an end of the enclosure 84being secured to a member (such as the inner sleeve 98) displaceable byan actuator 38, and in which the enclosure material 106 is opened inresponse to displacement of the member by the actuator 38.

An opposite end of the enclosure 84 may be secured against displacementrelative to the container 36. A fastener 78 may extend through folds ofthe flexible material 106 at the opposite end of the enclosure 84.

The member may comprise a closure member of a valve 92. The closuremember may comprise an inner sleeve 98, and the valve 92 may comprise asliding sleeve valve.

The closure member 98 may have a closed position that prevents fluidcommunication between an exterior of the dispensing tool 26 and aninterior flow passage 102 of the dispensing tool 26. The closure member98 may have an open position in which fluid communication is permittedbetween the exterior of the dispensing tool 26 and the interior flowpassage 102. The flow passage 102 may be in fluid communication with aninterior of the enclosure 84.

The above disclosure also provides to the art a plugging device 60 foruse in a subterranean well. In one example, the plugging device 60 caninclude at least one body 64 configured to engage an opening 68 in thewell and block fluid flow 74 through the opening 68; and multiple fibers62, the fibers 62 comprising staple fibers or filaments formed intoyarn.

The yarn may be twisted or braided and form cord or rope. The yarn maybe twisted or braided to form a larger yarn.

Each of the multiple fibers 62 may comprise multiple different polymersspun into an individual multi-component fiber 62. The different polymersmay have respective different degrees of crystallinity and/or respectivedifferent melting points.

The polymers may be selected from the group consisting of poly(L-lacticacid), poly(D-lactic acid-co-L-lactic acid), poly(glycolic acid),poly(lactic acid-co-glycolic acid), poly(paradioxanone),poly(ε-caprolactone), poly(L-lactic acid-co-ε-caprolactone),poly(L-lactic acid-co-trimethylene carbonate),poly(ε-caprolactone-co-glycolic acid-co-trimethylene carbonate),polybutylene succinate, poly(3-hydroxybutyrate-co-3-hydroxyvalerate),poly(L-lactic acid-block-ethylene glycol) and polyethyleneterephthalate.

An acid produced by a faster-degrading one of the polymers mayaccelerate degradation of a more stable one of the polymers. Adegradation rate of at least one of the polymers may be increased byaddition of a base or base precursor to the at least one of the polymersbefore spinning the fiber 62, or by inclusion of the base or baseprecursor in a coating on the fiber 62.

The base or base precursor may be selected from the group consisting ofalkaline earth oxides, alkaline earth hydroxides, calcium oxide,magnesium oxide, calcium hydroxide, magnesium hydroxide, zinc oxide,sodium tetraborate, calcium carbonate, hexamethylenetetramine and urea.

The polymers may comprise a combination of a water-soluble polymer and adegradable polymer. The water-soluble polymer may be selected from thegroup consisting of polyethylene oxide, polyvinyl acetate, polyvinylalcohol, methacrylic acid copolymers, copolymers of 2-ethylhexylacrylate and dimethylaminoethyl methacrylate and sulfopolyesters.

The multiple fibers 62 may comprise a hydrolysis-resistant material. Thehydrolysis-resistant material may be selected from the group consistingof carbon fiber, glass fiber, mineral fiber, ceramic fiber, meta-aramidfiber, para-aramid fiber, polyacrylonitrile fiber, polyparaphenylenesulfide fiber, polybenzanilide, polybenzimidazole fiber, polyethyleneterephthalate and fibers made from copolymers and blends. Thehydrolysis-resistant material may be selected from the group consistingof cotton, flax, hemp, sisal, jute, kenaf and coir.

Although various examples have been described above, with each examplehaving certain features, it should be understood that it is notnecessary for a particular feature of one example to be used exclusivelywith that example. Instead, any of the features described above and/ordepicted in the drawings can be combined with any of the examples, inaddition to or in substitution for any of the other features of thoseexamples. One example's features are not mutually exclusive to anotherexample's features. Instead, the scope of this disclosure encompassesany combination of any of the features.

Although each example described above includes a certain combination offeatures, it should be understood that it is not necessary for allfeatures of an example to be used. Instead, any of the featuresdescribed above can be used, without any other particular feature orfeatures also being used.

It should be understood that the various embodiments described hereinmay be utilized in various orientations, such as inclined, inverted,horizontal, vertical, etc., and in various configurations, withoutdeparting from the principles of this disclosure. The embodiments aredescribed merely as examples of useful applications of the principles ofthe disclosure, which is not limited to any specific details of theseembodiments.

In the above description of the representative examples, directionalterms (such as “above,” “below,” “upper,” “lower,” etc.) are used forconvenience in referring to the accompanying drawings. However, itshould be clearly understood that the scope of this disclosure is notlimited to any particular directions described herein.

The terms “including,” “includes,” “comprising,” “comprises,” andsimilar terms are used in a non-limiting sense in this specification.For example, if a system, method, apparatus, device, etc., is describedas “including” a certain feature or element, the system, method,apparatus, device, etc., can include that feature or element, and canalso include other features or elements. Similarly, the term “comprises”is considered to mean “comprises, but is not limited to.”

Of course, a person skilled in the art would, upon a carefulconsideration of the above description of representative embodiments ofthe disclosure, readily appreciate that many modifications, additions,substitutions, deletions, and other changes may be made to the specificembodiments, and such changes are contemplated by the principles of thisdisclosure. For example, structures disclosed as being separately formedcan, in other examples, be integrally formed and vice versa.Accordingly, the foregoing detailed description is to be clearlyunderstood as being given by way of illustration and example only, thespirit and scope of the invention being limited solely by the appendedclaims and their equivalents.

1-9. (canceled)
 10. A dispensing tool for dispensing plugging devicesinto a subterranean well, the dispensing tool comprising: a containerhaving an enclosure therein, the enclosure comprising a flexiblematerial that contains the plugging devices; and an end of the enclosurebeing secured to a member displaceable by an actuator, and in which theenclosure material is opened in response to displacement of the memberby the actuator.
 11. The dispensing tool of claim 10, in which anopposite end of the enclosure is secured against displacement relativeto the container.
 12. The dispensing tool of claim 11, in which afastener extends through folds of the flexible material at the oppositeend of the enclosure.
 13. The dispensing tool of claim 10, in which themember comprises a closure member of a valve.
 14. The dispensing tool ofclaim 13, in which the closure member comprises an inner sleeve, and inwhich the valve comprises a sliding sleeve valve.
 15. The dispensingtool of claim 13, in which the closure member has a closed position thatprevents fluid communication between an exterior of the dispensing tooland an interior flow passage of the dispensing tool.
 16. The dispensingtool of claim 15, in which the closure member has an open position inwhich fluid communication is permitted between the exterior of thedispensing tool and the interior flow passage.
 17. The dispensing toolof claim 15, in which the flow passage is in fluid communication with aninterior of the enclosure.
 18. A plugging device for use in asubterranean well, the plugging device comprising: at least one bodyconfigured to engage an opening in the well and block fluid flow throughthe opening; and multiple fibers, the fibers comprising staple fibers orfilaments formed into yarn.
 19. The plugging device of claim 18, inwhich the yarn is twisted or braided and forms cord or rope.
 20. Theplugging device of claim 18, in which the yarn is twisted or braided andforms a larger yarn.
 21. The plugging device of claim 18, in which eachof the multiple fibers comprises multiple different polymers spun intoan individual multi-component fiber.
 22. The plugging device of claim21, in which the different polymers have respective different degrees ofcrystallinity.
 23. The plugging device of claim 21, in which thedifferent polymers have respective different melting points.
 24. Theplugging device of claim 21, in which the polymers are selected from thegroup consisting of poly(L-lactic acid), poly(D-lactic acid-co-L-lacticacid), poly(glycolic acid), poly(lactic acid-co-glycolic acid),poly(paradioxanone), poly(ε-caprolactone), poly(L-lacticacid-co-ε-caprolactone), poly(L-lactic acid-co-trimethylene carbonate),poly(ε-caprolactone-co-glycolic acid-co-trimethylene carbonate),polybutylene succinate, poly(3-hydroxybutyrate-co-3-hydroxyvalerate),poly(L-lactic acid-block-ethylene glycol) and polyethyleneterephthalate.
 25. The plugging device of claim 21, in which an acidproduced by a faster-degrading one of the polymers acceleratesdegradation of a more stable one of the polymers.
 26. The pluggingdevice of claim 21, in which a degradation rate of at least one of thepolymers is increased by addition of a base or base precursor to the atleast one of the polymers before spinning the fiber, or by inclusion ofthe base or base precursor in a coating on the fiber.
 27. The pluggingdevice of claim 26, in which the base or base precursor is selected fromthe group consisting of alkaline earth oxides, alkaline earthhydroxides, calcium oxide, magnesium oxide, calcium hydroxide, magnesiumhydroxide, zinc oxide, sodium tetraborate, calcium carbonate,hexamethylenetetramine and urea.
 28. The plugging device of claim 21, inwhich the polymers comprise a combination of a water-soluble polymer anda degradable polymer.
 29. The plugging device of claim 28, in which thewater-soluble polymer is selected from the group consisting ofpolyethylene oxide, polyvinyl acetate, polyvinyl alcohol, methacrylicacid copolymers, copolymers of 2-ethylhexyl acrylate anddimethylaminoethyl methacrylate and sulfopolyesters.
 30. The pluggingdevice of claim 18, in which the multiple fibers comprise ahydrolysis-resistant material.
 31. The plugging device of claim 30, inwhich the hydrolysis-resistant material is selected from the groupconsisting of carbon fiber, glass fiber, mineral fiber, ceramic fiber,meta-aramid fiber, para-aramid fiber, polyacrylonitrile fiber,polyparaphenylene sulfide fiber, polybenzanilide, polybenzimidazolefiber, polyethylene terephthalate and fibers made from copolymers andblends.
 32. The plugging device of claim 30, in which thehydrolysis-resistant material is selected from the group consisting ofcotton, flax, hemp, sisal, jute, kenaf and coir.